The present invention relates to the elastic fluid turbines and more particularly to systems and methods for operating steam turbines and electric power plants in which generators are operated by steam turbines.
With respect to steam turbine control, prime mover turbine control usually operates to determine turbine rotor shaft speed, turbine load, and/or turbine throttle pressure as end control system variables. In the case of large electric power plants in which throttle pressure is steam-generating system controlled, turbine control is typically directed to the megawatt amount of electric load and the frequency participation of the turbine after the turbine rotor speed has been controllably brought to the synchronous value and the generator has been connected to the electric power system.
In addition to the conventional steam turbine generating system, another type of power generating system in which steam turbine control is needed is a combined cycle generating system. The combined cycle generating system involves a combination of heat sources and energy conversion apparatus organized to produce an electric power output. For example, gas turbines can drive generators and use their exhaust gases to supply heat for steam to be used in driving a steam turbine. A separate boiler can also be included in the system to provide steam generating heat. Electric power is supplied by separate generators driven by the turbines.
The end controlled plant or plant system variables and the turbine operation are normally determined by controlled variation of the steam flow to one or more of the various stages of the particular type and particular design of the turbine in use. In prime mover turbine applications such as drum type boiler electric power plants where turbine throttle pressure is externally controlled by the boiler operation, the turbine inlet steam flow is an end controlled steam characteristic or an intermediately controlled system variable which controllably determines in turn the end control system variables, i.e., turbine speed, electric load or the turbine speed and the electric load. It is noteworthy, however, that some supplemental or protective control may be placed on the end control variable by additional downstream steam flow control such as by control of reheat valving and to that extent inlet turbine steam flow control is not strictly wholly controllably determinative of the end controlled system variables under all operating conditions.
In determining turbine operation and the end controlled system variables, turbine steam flow control has generally been achieved by controlled operation of valves disposed in the steam flow path or paths. To illustrate the nature of the turbine valve control in general and to establish simultaneously some background for subsequent description, consideration will now be directed to the system structure and the operation of a typical large electric power tandem steam turbine design for use with a fossil fuel drum-type boiler steam generating system.
Steam generated at controlled pressure may be admitted to the turbine steam chest through one or more throttle or stop valves operated by the turbine control system. Governor or control valves are arranged to supply steam inlets disposed around the periphery of a high pressure turbine section casing. The governor valves are also operated by the turbine control system to determine the flow of steam from the steam chest through the stationary nozzles or vanes and the rotor blading of the high pressure turbine section.
Torque resulting from the work performed by steam expansion causes rotor shaft rotation and reduced steam pressure. The steam is usually then directed to a reheat stage where its enthalpy is raised to a more efficient operating level. In the reheat stage, the high pressure section outlet seam is ordinarily directed to one or more reheaters associated with the primary steam generating system where heat energy is applied to the steam. In large electric power nuclear turbine plants, turbine reheater stages are usually not used and instead combined moisture separator reheaters are employed between the tandem nuclear turbine sections.
Reheated steam crosses over the next or immediate pressure section of a large fossil fuel turbine where additional rotor torque is developed as intermediate pressure steam expands and drives the intermediate pressure turbine blading. One or more interceptor and/or reheater stop valves are usually installed in the reheat steam flow path or paths in order to cut off or reduce the flow of turbine contained steam as required to protect against turbine overspeed. Reheat and/or interceptor valve operation at best produces late corrective turbine response and accordingly is normally not used controllably as a primary determinant of turbine operation.
Additional reheat may be applied to the steam after it exits from the intermediate pressure section. In any event, steam would typically be at a pressure of about 1200 psi as it enters the next or low pressure turbine section usually provided in the large fossil fuel turbines. Additional rotor torque is accordingly developed and the vitiated steam then exhausts to a condenser.
In both the intermediate pressure and the low pressure sections, no direct steam flow control is normally applied as already suggested. Instead, steam conditions at these turbine locations are normally determined by mechanical system design subject to time delayed effects following control placed on the high pressure section steam admission conditions.
In a typical large fossil fuel turbine just described, 30% of the total steady state torque might be generated by the high pressure section and 70% might be generated by the intermediate pressure and low pressure sections. In practice, the mechanical design of the turbine system defines the number of turbine sections and their respective torque ratings as well as other structural characteristics such as the disposition of the sections or one or more shafts, the number of reheat stages, the blading and vane design, the number and form of turbine stages and steam flow paths in the sections, etc.
A variety of valve arrangements may be used for steam control in the various turbine types and designs, and hydraulically operated valve devices have generally been used for steam control in the various valving arrangements. The use of hydraulically operated valves has been predicated largely on their relatively low cost coupled with their ability to meet stroke operating power and positioning speed and accuracy requirements.
Turbine valve control and automatic turbine operation have undergone successive stages of development. With increasing plant sizes, mechanical-hydraulic controls have been largely supplanted by analog electrohydraulic controllers sometimes designated as AEH controllers. A coassigned Giras and Birnbaum U.S. Pat. No. 4,258,424, provides a further description of the turbine control technology development and the earlier prior patent and publication art. The latter application discloses a programmed digital computer controller which generally provides improved turbine and electric power plant operation over the earlier prior art. U.S. Pat. No. 3,588,265 issued to W. Berry, entitled System and Method For Providing Steam Turbine Operation With Improved Dynamics, and assigned to the present assignee, is also directed to a digital computer controller which provides improved automatic turbine startup and loading operations. U.S. Pat. No. 3,552,872 issued to T. Giras and T. C. Barns, Jr. entitled Computer Positioning Control System With Manual Backup Control Especially Adapted For Operating Steam Turbine Valves, and assigned to the present assignee, discloses a digital computer controller interfaced with a manual backup controller. A general publication pertaining to turbine digital controllers has appeared in Electrical World Magazine.
At this point in the background writeup, it is noted that prior art citations are made herein in an attempt to characterize the context within which the presently disclosed subject matter has been developed. No representations are made that the cited art is the best art nor that the cited art is immune to alternative interpretations.
Generally, the earlier Berry and the earlier Giras and Birnbaum DEH turbine operating system comprise basic hardware and software elements and control loops which bear some similarity to a number of basic elements and loops described herein. However, the present disclosure involves improvements largely stemming from the combined application of principles associated with turbine technology and principles associated with the computer and control technologies in the determination of a particular detailed system arrangement and operation. Thus, the earlier DEH is largely directed to central control concepts which, although implementable with conventional know-how, open up opportunities for improvement-type developement-type developments related to the more central aspects of turbine control and operation as well as the more supportive aspects of turbine control and operation including areas such as turbine protection, remote system interfacing, accuracy and reliability, computer utilization efficiency, operator interface, maintenance and operator training.
Specifically, one of the above mentioned improvement-type developments involves the improved monitoring capability of the DEH system disclosed herein, and the attendant capacity of the DEH to control turbine operation throughout startup subject to interrupt when unsatisfactory operating conditions are monitored. In prior art systems, contact closure inputs (CCI) are generally periodically scanned at a predetermined rate. However, this method of monitoring has two drawbacks. First, periodic contact scanning is inefficient in that such scanning is unnecessary when status contacts are not changing at a high rate, or are changing at a rate much slower than the scanning rate. Secondly, when a contact does change state, the periodic scanning method may not make this information available to the computer control system until a full scan period (e.g., one second) later. There has thus existed in the prior art a need for a more efficient means of monitoring turbine system conditions, i.e., for getting signals representative of such systems into the computer efficiently and when needed. Similarly, there has existed a need for a more efficient means of performing the analog scanning task for inputting analog signal information into the computer. The subject invention fulfills these needs and provides for direct computerized control of turbine operation throughout startup with the enhanced reliability obtained from the improved means for inputting data to and outputting data from the computer processor.